Oil field operators dedicate significant resources to improve the recovery of hydrocarbons from reservoirs while reducing recovery costs. To achieve these goals, reservoir engineers both monitor the current state of the reservoir and attempt to predict future behavior given a set of current and/or postulated conditions. Reservoir monitoring, sometimes referred to as reservoir surveillance, involves the regular collection and monitoring of measured near-wellbore production data from within and around the wells of a reservoir. Such data may be collected using sensors installed inline along production tubing introduced into the well. The data may include, but is not limited to, water saturation, water and oil cuts, fluid pressure and fluid flow rates, is generally collected at a fixed, regular interval (e.g., once per minute) and is monitored in real-time by field personnel. As the data is collected, it is archived into a historical database.
The production and survey data is incorporated into simulations that are executed as part of the well surveillance and model the behavior of the entire reservoir. Such simulations predict the current overall state, producing simulated interwell data values both near and at a distance from the wellbore. Simulated near-wellbore interwell data is regularly correlated against measured near-wellbore data, with modeling parameters being adjusted as needed to reduce the error between simulated and measured data. Once so adjusted, the simulated interwell data, both near and at a distance from the wellbore, may be relied upon to assess the overall state of the reservoir.
The collected production data, however, mostly reflects conditions immediately around the reservoir wells. To provide a more complete picture of the state of the reservoir, periodic surveys of the reservoir are performed. Such surveys can include large scale electromagnetic (EM) surveys that may be performed months or even years apart. The surveys can subsequently be combined to provide a time-lapse image of a reservoir to identify trends and adjust production strategies to optimize the production of the reservoir.
However, as a result of the large periods of time between surveys, the use of permanently deployed sensors (i.e., sensors expected to be deployed once and operated for the predicted lifespan of a reservoir) has largely been considered impractical. This is because the environments to which EM sensors are exposed are generally too harsh to operate existing sensors reliably over such long periods and too inaccessible to perform any sort of equipment maintenance, failure diagnosis or repair in a cost effective manner, if at all. This is true of both offshore and onshore environments. Offshore reservoirs may be located at significant depths where the pressure and salinity can take its toll on equipment and accessibility may be limited to remotely operated vehicles with limited capabilities and high deployment and operations costs. Onshore reservoirs may appear to be more accessible, but because onshore sensors and their corresponding communication and/or power networks must be buried underground, the cost of equipment maintenance, failure diagnosis and repair can still be substantial and in some cases prohibitive. Even absent overt failures, these hostile environments can still produce long-term shifts in the measurements taken by the sensors that render the measurements inconsistent as between surveys and preclude any meaningful correlation of the survey data.
It should be understood that the drawings and corresponding detailed description do not limit the disclosure, but on the contrary, they provide the foundation for understanding all modifications, equivalents, and alternatives falling within the scope of the appended claims.